When pumping oil (or for that matter water or other fluids) from wells driven into the ground, a downhole pump is often utilized wherein the pump is physically located deep within the well to pump the oil or fluid to the surface. In many such applications the downhole pump of choice is a screw or progressive cavity pump. Screw or progressive cavity pumps generally operate through the revolution of a pump rotor within a stationary housing or stator. In most instances a rotating pump rod extends from the surface down through the well to the pump to drive the rotor. A power supply, which would typically be comprised of a gas or diesel engine, or an electric motor, provides the mechanism by which the pump rod, and hence the pump rotor, is rotated.
In most oil and water well applications a production tubing string is positioned within the well casing about the pump rod and is connected to the pump to provide a conduit for the extraction of oil or fluids from the well. Commonly the upper end of the production tubing string is held within the well casing through the use of a variety of flanges, hangers (often referred to as dognuts) or similar devices. The bottom end of the tubing string is often secured to the casing by means of an anchor or no-turn tool. With the rotation of the rotor in a downhole progressive cavity pump there is a tendency to impart what in many cases is a very significant torque to the production tubing string.
Accordingly, a swivel is typically inserted within the production tubing string to prevent torque from being carried throughout the length of the string to the surface of the well.
It has been found that during production the type and quantities of fluids passing through the tubing string, as well as instances where the rotating pump rod comes into contact with the interior surface of the tubing string, can cause wear and erosion of the surface of the string. The degree of wear and erosion can increase significantly in deep wells, or in wells that are not perfectly vertical in orientation where the rod often contacts the string over a great distance. It is well know that through rotating the tubing string in a slow and constant manner, the wear that typically incurs on its inside surface can be more evenly distributed about the string, thereby significantly extending the tubing string's life and reducing the potential for equipment failure and the resulting and associated costs and lost production.
A variety of devices have been proposed by others to present a means to rotate the tubing string in order to more evenly distribute wear about the interior surface of the string. Commonly, such devices are mechanically operated tubing string rotators that comprise a housing that is bolted or otherwise attached to the wellhead. Through a mechanical linkage or gear system, an electric motor, a hydraulic motor, or other form of mechanical power source causes the tubing string rotator to slowly rotate the string within the casing. Such known tubing string rotators are described in U.S. Pat. Nos. 2,630,181, dated Mar. 3, 1953; 5,139,090, dated Aug. 18, 1992; 5,383,519, dated Jan. 24, 1995; 5,427,178, dated Jun. 27, 1995; 5,964,286, dated Oct. 12, 1999; and, 6,199,630, dated Mar. 13, 2001.
While existing tubing string rotators have been relatively effective in imparting a rotational movement to a tubing string in the manner described above, they also suffer from a number of limitations that affect their performance, reliability and cost. Not the least of these limitations stems from the fact that existing rotators rely upon a dedicated source of mechanical power to rotate the string. In the majority of applications a dedicated electric or hydraulic motor is mechanically connected to the rotator through a gear reduction system. In other applications a mechanical linkage may be utilized to transfer energy from an alternate wellhead source to cause rotation of the tubing string. In either case, the mode of imparting mechanical energy to the tubing string rotator adds to the physical complexity of the wellhead equipment, increases capital cost, presents a further opportunity for equipment failure (particularly where an electric motor is used) and can add significantly to energy consumption and operating costs.